The present invention relates generally to improved methods for evaluating subsurface fracture parameters in conjunction with the hydraulic fracturing of subterranean formations and more specifically relates to improved methods for utilizing test fracture operations and analysis, commonly known as "minifrac" operations, to design formation fracturing treatments.
A minifrac operation is performed to obtain information about the subterranean formation surrounding the well bore. Minifrac operations consist of performing small scale fracturing operations utilizing a small quantity of fluid to create a test fracture and then monitor the formation response by pressure measurements. Minifrac operations are normally performed using little or no proppant in the fracturing fluid. After the fracturing fluid is injected and the formation is fractured, the well is shut-in and the pressure decline of the fluid in the newly formed fracture is observed as a function of time. The data thus obtained are used to determine parameters for designing the full scale formation fracturing treatment. Conducting minifrac tests before performing the full scale treatment generally results in enhanced fracture designs and a better understanding of the formation characteristics.
Minifrac test operations are significantly different from conventional full scale fracturing operations. For example, as discussed above, typically a small amount of fracturing fluid is injected, and no proppant is utilized in most cases. The fracturing fluid used for the minifrac test is normally the same type of fluid that will be used for the full scale treatment. The desired result is not a propped fracture of practical value, but a small scale fracture to facilitate collection of pressure data from which formation and fracture parameters can be estimated. The pressure decline data will be utilized to calculate the effective fluid-loss coefficient of the fracturing fluid, fracture width, fracture length, efficiency of the fracturing fluid, and the fracture closure time. These parameters are then utilized in a fracture design simulator to establish parameters for performing a full scale fracturing operation.
Accurate knowledge of the fluid-loss coefficient from minifrac analysis is of major importance in designing a fracturing treatment. If the loss coefficient is estimated too low, there is a substantial likelihood of a sand out. Conversely, if the fluid leak-off coefficient is estimated too high, too great a fluid pad volume will be utilized, thus resulting in significantly increased cost of the fracturing operation and may often cause unwarranted damage to the formation.
Conventional methods of minifrac analysis are well known in the art and have required reliance upon various assumptions, some of which are of questionable validity. Current minifrac models assume that fluid-loss or leak-off rate is inversely proportional to the square root of contact time, which indicates that the formation is assumed to be homogeneous and that back pressure in the formation builds up with time, thus resisting fluid flow into the formation. In the conventional minifrac analysis as described in U.S. Pat. No. 4,398,416 to Nolte, the pressure decline function, G, is always determined using this assumption. However not all formation/fluid systems have a leak-off rate inversely proportional to the square root of time.
As stated above, in conventional minifrac analysis the formation is presumed to be homogeneous. Consequently, the derived equations of conventional minifrac analysis do not accurately apply to heterogeneous formations, e.g., naturally fractured formations. A naturally fractured formation contains highly conductive channels which intersect the propagating fracture. In a naturally fractured formation, fluid-loss occurs very rapidly due to the increased formation surface area. Consequently, depending on the number of natural fractures that intersect the propagating fracture, the fluid loss rate will vary as a function of time raised to some exponent.
In Paper 15151 of the Society of Petroleum Engineers and U.S. Pat. No. 4,749,038, Shelley and McGowen recognized that conventional minifrac analysis techniques when applied to naturally fractured formations failed to adequately predict formation behavior. Shelley and McGowen derived an empirical correlation for various naturally fractured formations based on several field cases. However, such empirical correlations are strictly limited to the formations for which they are developed.
The present invention provides modifications to minifrac analysis techniques which makes minifrac analysis applicable to all types of formations, including naturally fractured formations, without the need for specific empirical correlations. The present invention also introduces a new parameter, the leak-off exponent, that characterizes fracturing fluid and formation systems with respect to fluid loss.